CALGARY, ALBERTA–(Marketwired – Feb. 1, 2017) – Bonavista Energy Corporation (“Bonavista”) (TSX:BNP) is pleased to report that our 2016 exploration and development (“E&D”) program has resulted in a finding and development (“F&D”) cost of $6.97 per barrel of oil equivalent (“boe”) on a proved plus probable basis. When combined with our acquisition and divestiture program (“A&D”), finding, development and acquisition (“FD&A”) costs were $(0.55) per boe on a proved plus probable basis, in each case including changes in future development costs (“FDC”).
2016 Reserves Highlights:
The success we have experienced in the execution of our 2016 capital program continues to reinforce the quality and reliability of the opportunities that exist in our core areas as demonstrated by the highlights listed below:
- Replaced 131% of 2016 production with the addition of 32.8 MMboe of proved plus probable reserves at no cost with net A&D proceeds exceeding our E&D expenditures;
- Added 30.8 MMboe of proved plus probable reserves with our E&D program spending only 58% of our funds from operations to replace 123% of 2016 production;
- Achieved F&D costs of $6.97 per boe on a proved plus probable basis, including changes in FDC, resulting in a recycle ratio of 1.9:1 despite an 18% erosion in realized revenue per boe in 2016 relative to 2015;
- Acquired 38.9 MMboe and divested 37.0 MMboe of proved plus probable reserves resulting in FD&A costs of $(0.55) per boe on a proved plus probable basis, including changes in FDC;
- Reduced our proved developed producing (“PDP”) F&D to $9.71 per boe compared to $11.94 per boe in 2015, a 19% improvement; and
- Using the independent reserves evaluation effective December 31, 2016, the net present value of future net revenues discounted at 10% (“PV10”) before taxes of our proved plus probable reserves, net of estimated debt of $878 million equates to $7.36 per common share (based on 253.9 million equivalent basic common shares outstanding). With the addition of an internally estimated total land value of $144.6 million, our net asset value would be approximately $7.93 per share.
For the year ended December 31, 2016, we invested $153.9 million (unaudited) into the development of the key plays in our two core areas drilling 46 (43.1 net) wells resulting in average production of 68,550 boe per day. During the fourth quarter, we drilled 17 (15.9 net) wells generating production of 69,339 boe per day, and currently are producing approximately 71,000 boe per day. Specific operational highlights include the following:
- Reduced 2016 cash costs by 12% to $9.40 per boe when compared to the same period in 2015;
- Reduced our cost to add production through our E&D program by 23% to $13,600 per boe per day when compared to 2015;
- Successfully integrated the assets acquired through the asset exchange which closed in mid-October. Current production from these assets is approximately 6,900 boe per day. We expect to drill 14 wells and generate $44 million of funds from operations on these assets in 2017;
- In December, we closed the previously announced dispositions of 2,900 boe per day for proceeds of $118 million, instrumental in our total corporate debt reduction of $430 million in 2016; and
- Currently we are operating five drilling rigs, three of which are at our Ansell Wilrich development.
2016 Independent Reserves Evaluation:
The evaluation of our reserves was done in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Additional reserves information as required under NI 51-101 will be included in our Annual Information Form which will be filed on SEDAR on or before March 31, 2017.
Independent reserve evaluators, GLJ Petroleum Consultants Ltd. (“GLJ”) evaluated 92% of our total net present value reserves (calculated using a discount rate of 10%) and the balance of our proved plus probable net present value reserves were evaluated internally and reviewed by GLJ in their report dated January 26, 2017 and effective December 31, 2016 (the “GLJ Report”).
The following tables summarize our working interest oil, natural gas liquids and natural gas reserves and the net present values (“NPV”) of future net revenue for these reserves (before taxes) using forecast prices and costs as set forth in the GLJ Report.
|NPV of Future Net
Revenue Discounted at
|Total Proved plus Probable||1,721,037||11,169||116,197||414,205||3,875,818||2,747,696||2,091,855|
|(1) Amounts may not add due to rounding.|
|(2) Includes conventional natural gas, shale natural gas and coal bed methane.|
|(3) Includes light, medium, heavy and tight oil.|
The reserves evaluation was based on GLJ forecast pricing and foreign exchange rates at January 1, 2017 as outlined below. The GLJ January 1, 2017 forecast pricing for natural gas at AECO and West Texas Intermediate (“WTI”) oil are CDN$3.46/MMBtu and US$55.00/bbl respectively. This represents a 6% increase in forecast natural gas pricing and a 6% increase in forecast 2017 WTI oil pricing when compared to GLJ’s forecast pricing for 2017 at January 1, 2016.
Light Crude Oil
|RECONCILIATION OF GROSS RESERVES BY PRINCIPAL PRODUCT TYPE FORECAST PRICES AND COSTS(1)|
|LIGHT AND MEDIUM OIL||HEAVY OIL|
|December 31, 2015||17,476||7,939||25,416||498||153||651|
|Extensions and Improved Recovery(2)||384||35||419||–||–||–|
|December 31, 2016||7,511||3,111||10,622||417||130||547|
|NATURAL GAS||NATURAL GAS LIQUIDS|
|December 31, 2015||1,025,960||575,745||1,601,705||73,256||40,221||113,477|
|Extensions and Improved Recovery(2)||146,110||53,833||199,943||8,768||2,297||11,064|
|December 31, 2016||1,128,147||592,891||1,721,037||77,231||38,966||116,197|
|December 31, 2015||262,224||144,270||406,494|
|Extensions and Improved Recovery(2)||33,503||11,304||44,808|
|December 31, 2016||273,183||141,022||414,205|
|(1) Amounts may not add due to rounding.|
|(2) Infill drilling, improved recovery and extensions have been grouped as extensions and improved recovery as per NI 51-101.|
Reserve Life Index (“RLI”):
Our business plan is to create premium shareholder value through the efficient development of high quality oil and natural gas assets. The profitable growth of our reserves coupled with the sustainable production of these reserves will generate long term returns for our shareholders.
In 2016, our proved plus probable RLI increased by 2% to 14.4 years demonstrating the sustainable balance that exists between our capital program, our reserves additions and our production levels. The production decline characteristics of our asset portfolio influence our RLI. For 2017, GLJ is forecasting a proved developed producing decline rate of 22.6%.
The following table highlights our historical RLI.
|Reserve Life Index (Years)(1)||2016||2015||2014||2013||2012|
|Total Proved plus Probable||14.4||14.1||13.1||13.2||13.5|
|(1) Calculated based on the amount for the relevant reserves category divided by the production forecast for the applicable year prepared by GLJ.|
Future Development Costs:
Changes in forecast FDC occur annually and result from development, acquisition and disposition activities. Future development cost estimates reflect GLJ’s best estimate of the costs required to bring the proved and proved plus probable reserves on production. We have 195.2 MMboe reserves assigned to $1,270.2 million of FDC. At a cost of $6.51 per boe, these future reserves generate $998 million of net present value discounted at 10%.
Current year FDC as a ratio of trailing average three year E&D expenditures of $369.1 million is 3.6:1 times, representing prudent and sustainable development forecasts.
The following table sets forth the schedule of FDC required to develop these future reserves (using forecast prices and costs).
|Future Development Costs||Total Proved||Total Proved
|($ thousands)||($ thousands)|
|Total (Discounted at 10%)||766,015||1,058,928|
Reserves Performance Ratios:
The following tables highlight Bonavista’s reserves, F&D costs and FD&A costs and the associated recycle ratios. Throughout the year, Bonavista experienced significant improvements in capital efficiencies specifically improving PDP F&D cost by 19% to $9.71 per boe and proved plus probable F&D cost by 4% to $6.97 per boe. Furthermore, we enhanced these results with our acquisition and divestiture strategy resulting in a combined PDP FD&A cost of $(0.86) per boe and proved plus probable FD&A cost of $(0.55) per boe.
Bonavista considers recycle ratio an important measure of profitability. It is measured by dividing the operating netback by the F&D costs per boe for the year. Bonavista delivered an F&D recycle ratio of 1.9:1 for proved plus probable reserves including revisions and changes in future development costs.
|Proved plus probable||414,205||406,494||426,767|
|Capital Expenditures ($ millions):|
|Acquisitions, net of dispositions||(167.9||)||(30.6||)||(106.8||)|
|Total capital expenditures||(14.0||)||283.4||532.8|
|Operating Netback ($/boe)(1):|
|Three-year weighted average||17.54||19.72||20.37|
|(1) Amounts may not add due to rounding.|
|Finding and Development Costs:||2016||2015||2014|
|Change in FDC ($ millions)||(0.2||)||(0.3||)||(4.0||)|
|Reserves additions (MMboe)||15.8||26.3||49.5|
|F&D costs ($/boe)(2)||9.71||11.94||12.84|
|F&D recycle ratio(3)||1.4||1.4||1.8|
|F&D three-year weighted costs ($/boe)(2)||12.04||13.57||14.90|
|F&D recycle ratio three-year weighted average(3)||1.5||1.5||1.4|
|Change in FDC ($ millions)||86.4||(188.7||)||1.3|
|Reserves additions (MMboe)||27.0||20.3||49.5|
|F&D costs ($/boe)(2)||8.91||6.15||12.96|
|F&D recycle ratio(3)||1.5||2.6||1.7|
|F&D three-year weighted costs ($/boe)(2)||10.40||12.21||14.70|
|F&D recycle ratio three-year weighted average(3)||1.7||1.6||1.4|
|Total Proved plus Probable:|
|Change in FDC ($ millions)||60.9||(183.5||)||(19.1||)|
|Reserves additions (MMboe)||30.8||18.0||57.1|
|F&D costs ($/boe)(2)||6.97||7.26||10.86|
|F&D recycle ratio(3)||1.9||2.2||2.1|
|F&D three-year weighted costs ($/boe)(2)||9.11||10.65||12.21|
|F&D recycle ratio three-year weighted average(3)||1.9||1.9||1.7|
|Finding, Development and Acquisition Expenditures:||2016||2015||2014|
|Change in FDC ($ millions)||(2.3||)||4.7||1.1|
|Reserves additions (MMboe)||18.9||21.5||42.8|
|FD&A costs ($/boe)(2)||(0.86||)||13.37||12.49|
|FD&A recycle ratio(3)||(15.6||)||1.2||1.8|
|FD&A three-year weighted costs ($/boe)(2)||9.69||13.35||13.43|
|FD&A recycle ratio three-year weighted average(3)||1.8||1.5||1.5|
|Change in FDC ($ millions)||111.6||(186.0||)||45.0|
|Reserves additions (MMboe)||36.0||15.4||47.6|
|FD&A costs ($/boe)(2)||2.71||6.32||12.13|
|FD&A recycle ratio(3)||5.0||2.6||1.9|
|FD&A three-year weighted costs ($/boe)(2)||7.81||12.10||13.05|
|FD&A recycle ratio three-year weighted average(3)||2.2||1.6||1.6|
|Total Proved plus Probable:|
|Change in FDC ($ millions)||(3.8||)||(198.6||)||28.2|
|Reserves additions (MMboe)||32.8||8.6||56.4|
|FD&A costs ($/boe)(2)||(0.55||)||9.84||9.95|
|FD&A recycle ratio(3)||(24.4||)||1.6||2.3|
|FD&A three-year weighted costs ($/boe)(2)||6.42||10.42||10.71|
|FD&A recycle ratio three-year weighted average(3)||2.7||1.9||1.9|
|(1) Operating netback is calculated using production revenues including realized gains and losses on financial instrument commodity contracts less royalties, transportation and operating expenditures, calculated on a per boe basis.|
|(2) Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis.|
|(3) Recycle ratio is defined as operating netback per boe divided by either F&D or FD&A costs per boe.|
Reaffirmed 2017 Guidance:
Our 2017 program is forecasted to provide nine percent production growth and 18% growth in funds from operations, all on a debt and dividend adjusted per share basis. This growth will be provided while maintaining a total payout ratio in the range of 90% to 95% with excess funds used to further improve our financial flexibility. The table below summarizes our reaffirmed 2017 guidance:
|Payout ratio (%)||90 – 95|
|E&D capital expenditures ($ millions)||280 – 300|
|Production (boe/d)||73,500 – 75,500|
|Funds from operations ($ millions)||300 – 350|
|Dividends ($ millions)||10|
|Wells (net)||55 – 60|
|WTI oil (US$/bbl)||53.00|
|AECO natural gas (CDN$/gj)||2.85|
|Exchange rate ($CDN/$US)||0.75|
We regularly assess the impact of changes in commodity prices and foreign exchange rates on our business. As such, our 2017 capital budget will remain flexible to accommodate the commodity price volatility.
Hedging & Commodity Marketing:
Bonavista has secured market egress and access for 2017. Bonavista has arranged for firm transportation on the Nova Gas Transmission Ltd. (“NGTL”) system north of the James River receipt point (“restricted area”) equal to 116% of our forecasted natural gas sales in this area.
Bonavista has also continued to prudently add to our commodity hedge positions. Currently 74% of our forecasted 2017 natural gas production is hedged at an AECO price of $2.94 per gj and we have approximately 10% of our natural gas volumes contracted for delivery to the U.S. Midwest markets. Lastly, we have 75% of oil (oil and condensate) volumes hedged and 49% of our propane volumes hedged for 2017.
Bonavista is focused on creating premium shareholder value through the efficient development of high quality oil and natural gas assets.